Natural gas is bought and sold based on its heating value. It is the BTU content that determines the monetary value of a given volume of natural gas. This BTU value is generally expressed in decatherms (one million BTU). In the determination of total heat value of a given volume of gas, a sample of the gas is analyzed and from the composition its heat value per unit volume is calculated. This value is generally expressed in BTU/cu ft. The typical range of transmission quality gas ranges between 1000 and 1100 BTU/cu ft. Production gas can have heating values exceeding 1500 BTU/cu ft.
There has been a long standing controversy between gas producers and gas transporters regarding entrained liquid typically present in most high BTU/cu ft gas (rich or wet gas). Transporter tariffs require essentially liquid-free gas. Hydrocarbon liquid in the gas being transported causes operational and safety problems. The practice is to separate the liquid before entering a transport (pipe) line.
The API 14.1 standards (Manual of Petroleum Measurement Standards, 2006) scope does not include “wet gas” (a term referenced by the Natural Gas industry as a gas that is at its hydrocarbon dew point temperature and/or contains entrained liquid), nor does the GPA 2166 standard (Obtaining Natural Gas Samples for Analysis by Gas Chromatography, 2005). In summary, there is no known standard which defines how to obtain a “representative sample” of a natural gas supply having entrained hydrocarbon in any form.
The liquid hydrocarbon (HC) content of a Natural Gas is comprised mainly of the heavier (higher molecular weights such as propane, ethane and octane) components. Therefore its heating value is high, and of great monetary value. This is the reason that producers wish to have the liquid HC represented in the sample composition utilized for computing the BTU/cu ft content.
The API 14.1 standard, Appendix B section B-3 Multiphase Flow states that:                “Sampling of multiphase flow is outside the scope of this standard. Sampling of multiphase (gas and liquid) mixtures is not recommended and should be avoided if at all possible. In the multiphase flow, the ideal system would mix the gas and liquid flows uniformly and collect a sample of the true mixture flowing in the line by using a properly designed sample probe and an isokinetic sampling system. Current technology of natural gas sampling is not sufficiently advanced to accomplish this with reasonable accuracy. When sampling a multiphase liquid-gas flow, the recommended procedure is to eliminate the liquid from the sample. The liquid product that flows through the line should be determined by another method. The liquid fraction of the multiphase flow may contain water and hydrocarbons. The hydrocarbons can contribute significantly to the energy (measured in British thermal units) content of the gas and their presence in the gas line must not be overlooked.”        
The GPA 2166 standard's scope states that the standard is not designed for sampling Natural gas that is at or below its HC dew point temperature. Within the body of this standard several references are made to avoiding liquid entrainment and condensation due to its impact on sample composition and the calculated heat value.
The API 14.1 and GPA 2166 are the primary standards utilized by most Gas companies to guide their sampling methods. Both state that they are not intended for obtaining a Natural Gas sample representing a combined gas and liquid.
There have been many attempts to achieve the representative sampling of Natural Gas/HC liquid mixture. Most methods use a dynamic flow isokinetic technique. In an ideal world, gas having liquid droplets suspended would be directed into the entrance port of a sample probe (isokinetic probe), without changing its velocity or direction of liquid droplets.
To accomplish this, the supply gas velocity must be known, 1) the gas velocity at the probe entrance must be maintained equal to the supply gas velocity, and 2) the probe entry design must be shaped such as not to disturb the flow pattern of the liquid droplets. This approach, even under closely controlled conditions, is not accurate enough for custody transfer measurement. Therefore, it is neither a good nor a practical method for sampling wet gas on an “ongoing” basis.
Additionally, there are two other forms of liquid which may be present in the transport line other than suspended liquid droplets. One form is a liquid film which is always present when suspended droplets are flowing with the gas stream. Another form is liquid which at times flows along the bottom of the transport pipe. It is never known how the liquid is distributed between these three forms. Therefore measurement of only the suspended droplets is not on indication of the total liquid present in the transport line.
There is a company named Petrotech of Kvala, Norway (hereinafter PETROTECH) which utilizes an isokinetic Natural gas technique called ISOSPLIT®. The method consists of static mixing the two phases followed by dynamic isokinetic sampling of the resulting mixture. As previously stated, this technique is difficult to execute and produces less than desirable results. It is primarily employed at the well head. The PETROTECH U.S. Pat. No. 5,538,344 relates primarily to the positioning of a mixing body within a pipeline.
Another reason for requiring accuracy in the sampling of wet natural gas is that reservoir simulation models are based on compositional analysis, and gas allocations are also made on that basis.
With the dynamic isokinetic sampling technique, sample gas flows continuously during the sampling process.
In conclusion, the above isokinetic sampling systems are designed to insure an isokinetic fluid flow of process gas into the opening of a probe and therethrough to an external location. With such a configuration, the fluid stream velocity must be known and the fluid velocity entering the probe must be controlled, which makes the technique generally impractical for typical field sampling of fluids.